Natural gas conveyed through gas transmission pipelines is typically accompanied by minor proportions of water vapor and one or more vaporized liquid hydrocarbons. While these minor proportions of the later components are liquids at ambient pressure and temperature, the prevailing conditions in the pipeline will keep these compounds in a vaporized state. To the extent that some of these minor components condense on the interior walls of the pipeline, they can be removed by appropriate knock-out traps. However, for the purposes of obtaining an accurate analysis of the content of the fluid stream, such as for certifying its BTU value in a custody transfer context, or determining what downstream treatments may be required for removing undesired water vapor and/or certain types of vaporized hydrocarbons in a process stream feeding a reactor, current analytical methods and apparatus are found to be lacking.
As used herein the term “phase” means a type of fluid that can exist in contact with other fluids in a vaporized gaseous state or in a liquid state. A “multi-phase” fluid is a fluid containing more than one phase, i.e., liquid and gas, and can include a fluid having two or more liquid phases and/or a combination of a gas phase with one or more liquid phases. As will be understood by one of ordinary skill in the art, a mixture of hydrocarbon liquids, natural gas vapors and water includes a discrete hydrocarbon liquid and a discrete water phase as well as a discrete vapor phase containing water and hydrocarbon gases.
As used herein, the term “multi-phase fluid” includes a stream comprising natural gas, hydrocarbon liquids in the form of a stream, and/or small discrete drops or droplets, vaporized hydrocarbon liquids, water in the form of a stream and/or droplets and water vapor.
It is common for a natural gas stream to contain multiple fluid phases. As will be understood by one of ordinary skill in the art, gas transmission pipelines can be subjected to extreme temperature swings, e.g., daytime to nighttime changes of 60° F., or more, when taken at the same geographical location, and similar changes associated along the length of a pipeline where the altitude and associated temperature varies in mountainous terrain, as well as with exposure to sunlight. In these circumstances, the content of the fluid stream at a given point can change from a 100% vapor composition as the containing pipeline reaches its highest temperature, to a significant dropout and formation of liquid droplets of hydrocarbon and water as the pipeline cools to its lowest temperature. As is well known in the art, significant difficulties are associated with obtaining truly representative samples of the fluid from pressurized pipelines and in providing the sample in a state that is analyzable by any of the number of known standard techniques.
These limitations represent a serious problem to the industry, since there are approximately 1.5 million natural gas wells worldwide, many of which produce a multi-phase fluid flow of natural gas, hydrocarbon liquids and water, called “wet gas”. This condition is present in both raw well gas and in processed sales gas pipelines. In order for natural gas suppliers in some areas of the world to meet demand over the next ten to twenty years, it will be necessary to increase production from off-shore deep-water fields. Gas produced from such deep-water fields contains higher concentrations of low volatility components, including water vapor and heavy hydrocarbons that have a greater susceptibility to condense then gas from on-shore and off-shore shelf production areas.
During transmission or transport through pipelines, heavier gas components tend to condense out along the pipeline walls. Furthermore, when the fluid stream is sampled, additional condensation can occur due to the temperature and pressure differences between the mixture in the pipeline and in the sampling apparatus. Since the condensed components of the gas are commonly the heavy ends that are also rich in BTU content, these condensed components may never be analyzed because they cling to the walls of the equipment or drip back into the pipeline. Thus, the sample that is obtained where these conditions are prevalent is biased “lean”, with the result that the BTU content of the gas flow in the pipeline is actually greater than that of the non-representative sample.
The BTU heating value of natural gas obviously has a significant impact on its monetary value. In general, the heating value of natural gas increases as the concentration of low volatility, high molecular weight components increases.
Mathematical models have been proposed, but none have been found that reliably predicts the flow regime of three-phase flowing fluids.
The American Petroleum Institute (API), International Standards Organization (ISO) and the Gas Processors Association (GPA) are among the leading industry organizations that have long recognized the problems and deficiencies in obtaining and analyzing representative samples. Currently, the petroleum industry has no suitable technology for extracting samples of a natural gas containing any form of liquid that is proportional to the liquid load of the source gas. These organizations have stated that the liquid phase should be removed from the source gas and measured separately.
One method recommended in the prior art literature utilizes a separator that is best suited for removal of liquid slugs and large droplets. Liquid aerosols, which are the most frequent source of liquid entrainment, are not easily separated from the sample gas by the proposed knock-out type of separator.
Another method teaches the heating of the sampling equipment to a temperature above the dew point of the components of the flowing gas while the sample is being taken. This approach proves impractical since electric power for heating is typically not available in the field at the pipeline sampling point. Condensation of gas phase components, which reduce the proportion of high molecular weight components, therefore tends to decrease gas phase heating value, while vaporization of entrained liquid has the opposite effect.
For custody transfer measurements, liquids entrained in natural gas are the source of many problems in sample conditioning systems. Since a small volume of liquid is equivalent to several hundred times its volume of gas, even microscopic amounts of hydrocarbon aerosol droplets can have a significant impact on gas composition and BTU value measurements.
The impact of poor and inaccurate sampling methods and apparatus also has a direct effect on flow measurement since typical measurement methodologies require the density of the fluid to determine the volumetric flow rate. Thus, in gas production operations, problems arise when a flow meter is used to measure rates in the combined multi-phase stream. Specifically, flow characteristics such as density in differential pressure change. These changing flow characteristics produce inaccurate readings in conventional metering devices. The accuracy of these measurements are particularly important to gas merchants and consumers, such as public and private utilities, since the liquid-gas composition of the fluid stream determines the royalties to be paid to the producers. This information also indicates how quickly a natural gas reservoir is being depleted. Multi-phase flow meters are designed to provide a direct measurement of the combined flowing fluid stream, but this measurement cannot be directly resolved into individual measurements of the respective phases.
It is known in the petroleum industry to use well test equipment to separate gas, gas liquids and water phases from the gas well flow stream. Test separators are expensive, occupy valuable space on production platforms and require a relatively long time to provide an accurate monitoring of a given well because of the stabilized flow pattern that is required. Additionally, it has been found that test separators are only moderately accurate, e.g., typically plus or minus 5-10% of each phase flow rate; these devices cannot be used for continuous flow monitoring.
Separation equipment used in the prior art has included large and bulky vessel-type separation devices that include a horizontal or vertically disposed oblong pressure vessel together with at least one internal valve and weir assembly. Industry terminology refers to a “two-phase” separator to describe separation of a gas phase from a liquid phase, the latter including oil and water. Such two-phase separators do not allow direct volumetric measurements of segregated oil and water components under actual producing conditions. A “three-phase” separator separates the gas from the liquid phases and further separates the liquid phase into oil and water phases. As compared to the two-phase separators, three-phase separators require additional valve and weir assemblies, as well as larger contained volumes to provide the longer residence times needed for separation of produced liquids.
A method of determining the quality of steam that mixes a surfactant with the steam to produce a stable foam is disclosed in U.S. Pat. No. 5,470,749. The foam is admitted to a capillary tube and a specific electrical measurement is obtained that can be related to steam quality by application of an algorithm. This patent also suggests that the method can be used for the purpose of determining the relative amounts of gas and liquid in a flowing multi-phase stream, where the liquids are nonconductive or only slightly conductive. However, no examples are provided for sampling and quality analysis except for steam. Importantly, the quality determination appears to be based upon calibration requirements, and no examples are provided for calculations relating to organic solvents and hydrocarbons.
A surfactant or surface-active agent, is any compound that reduces surface tension when dissolved in water or water solutions or which reduces interfacial tension between two liquids. The three generally recognized categories of surface active agents are detergents, wetting agents and emulsifiers. All three use the same basic chemical mechanism and differ chiefly in the nature of the surfaces involved. Detergents are classed as anionic, cationic or non-ionic, depending on their mode of chemical action. The non-ionic compounds function by a hydrogen bonding mechanism.
It is therefore one object of the present invention to provide apparatus and methods for accurately sampling and analyzing multi-phase fluids that overcome the problems of the prior art. In particular, it is an object of the present invention to provide apparatus and methods employing surface active foaming agents that are more accurate than those known to the prior art.
Another object of the invention is to provide an apparatus and methods that can be practiced at pipeline sampling points in the field where limited utilities and facilities are available to provide homogenized samples for direct testing or for recovery of samples in sample storage vessels that will be used to deliver the samples for analysis at a remote location.
A further specific object of the invention is to provide an improved apparatus that is skid-mounted and portable for use in field locations.
Yet another object of the invention is to provide an improved apparatus and method employing foaming agents in wet gas metering applications that is more accurate and economical than known techniques.
It is another object of the invention to provide an apparatus and method that can be used in place of prior art two-and three-phase test separators to obtain reliable and accurate multi-phase fluid flow measurements and for the reliable recovery of representative fluid samples from the flowing fluid stream.
Another object of the invention is to provide an apparatus and methods for sampling a flowing pressurized multi-phase fluid stream that will permit highly accurate measurements of the stream density, as well as the proportions of the various components in the mixture.
A further object of this invention is to provide a method and apparatus for moving a foam in a wet gas transmission pipeline and thereby enhance pump efficiency and energy savings.
Another object of the invention is to provide an improved method for applying a liquid corrosion inhibitor to pipe walls that will enhance corrosion inhibition in pipelines where water is present in the hydrocarbon stream.